Ex 99.2

INDIANA GAS COMPANY, INC.

REPORTING PACKAGE

For the year ended December 31, 2005

Contents

	Page  Number
Audited Financial Statements
Independent Auditors’ Report	2
Balance Sheets	3-4
Statements of Income	5
Statements of Cash Flows	6
Statements of Common Shareholder’s Equity	7
Notes to Financial Statements	8
Results of Operations	21
Selected Operating Statistics	23

Additional Information

This annual reporting package should be read in conjunction with the annual reports of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of Indiana Gas, filed on Form 10-K for the year ended December 31, 2005. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through Vectren's website at www.vectren.com.

Frequently Used Terms

AFUDC: allowance for funds used during construction	MCF / MMCF / BCF: thousands / millions / billions of cubic feet
APB: Accounting Principles Board	MDth / MMDth: thousands / millions of dekatherms
EITF: Emerging Issues Task Force	OUCC: Indiana Office of the Utility Consumer Counselor
FASB: Financial Accounting Standards Board	PUCO: Public Utilities Commission of Ohio
FERC: Federal Energy Regulatory Commission	SFAS: Statement of Financial Accounting Standards
IDEM: Indiana Department of Environmental Management	USEPA: United States Environmental Protection Agency
IURC: Indiana Utility Regulatory Commission	Throughput: combined gas sales and gas transportation volumes

1

INDEPENDENT AUDITORS’ REPORT

To the Shareholder and Board of Directors of Indiana Gas Company, Inc.:

We have audited the accompanying balance sheets of Indiana Gas Company, Inc. (the “Company”) as of December 31, 2005 and 2004, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.An audit also includes examining,on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 

DELOITTE & TOUCHE LLP

Indianapolis, Indiana

February 16, 2006

2

FINANCIAL STATEMENTS

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2005		2004
ASSETS
Utility Plant
Original cost	$	1,300,342	$	1,251,508
Less: accumulated depreciation & amortization		451,038		424,118
Net utility plant		849,304		827,390
Current Assets
Cash & cash equivalents		5,609		1,624
Accounts receivable - less reserves of $1,282 &
$718, respectively		72,208		58,554
Receivables due from other Vectren companies		551		234
Accrued unbilled revenues		121,462		86,334
Inventories		14,818		14,074
Recoverable fuel & natural gas costs		4,953		13,728
Prepayments & other current assets		79,502		66,442
Total current assets		299,103		240,990
Investment in the Ohio operations		226,249		220,779
Other investments		5,538		3,050
Non-utility property - net		101		152
Regulatory assets		19,962		19,890
Other assets		5,380		3,123
TOTAL ASSETS	$	1,405,637	$	1,315,374

The accompanying notes are an integral part of these financial statements.

3

INDIANA GAS COMPANY, INC.

BALANCE SHEETS

(In thousands)

	December 31,
	2005		2004
LIABILITIES & SHAREHOLDER'S EQUITY
Common Shareholder's Equity
Common stock (no par value)	$	367,995	$	367,995
Retained earnings		90,599		86,582
Total common shareholder's equity		458,594		454,577
Long-term debt payable to third parties - net
debt subject to tender		127,500		167,417
Long-term debt payable to Utility Holdings		184,437		184,448
Total long-term debt, net		311,937		351,865
Commitments & Contingencies (Notes 3, 4, 7, 8 & 9)
Current Liabilities
Accounts payable		28,424		32,111
Accounts payable to affiliated companies		117,189		62,549
Payables to other Vectren companies		7,749		5,690
Accrued liabilities		57,893		49,339
Short-term borrowings payable to Utility Holdings		162,845		109,211
Long-term debt subject to tender		-		10,000
Total current liabilities		374,100		268,900
Deferred Income Taxes & Other Liabilities
Deferred income taxes		81,980		75,576
Regulatory liabilities		142,994		132,825
Deferred credits & other liabilities		36,032		31,631
Total deferred income taxes & other liabilities		261,006		240,032
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	1,405,637	$	1,315,374

The accompanying notes are an integral part of these financial statements.

4

INDIANA GAS COMPANY, INC.

STATEMENTS OF INCOME

(In thousands)

	Year Ended December 31,
	2005			2004
OPERATING REVENUES	$	831,741		$	686,103
COST OF GAS		595,940			474,452
GAS OPERATING MARGIN		235,801			211,651
OPERATING EXPENSES
Other operating		94,762			89,820
Depreciation & amortization		46,778			45,049
Taxes other than income taxes		21,616			18,453
Total operating expenses		163,156			153,322
OPERATING INCOME		72,645			58,329
OTHER INCOME (EXPENSE)
Equity in earnings of the
Ohio operations - net of tax		5,470			7,207
Other income (expense) - net		(901	)		(1,028	)
Total other income		4,569			6,179
Interest expense		27,785			29,157
INCOME BEFORE INCOME TAXES		49,429			35,351
Income taxes		17,088			10,915
NET INCOME	$	32,341		$	24,436

The accompanying notes are an integral part of these financial statements.

5

INDIANA GAS COMPANY, INC.

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	32,341		$	24,436
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization		46,778			45,049
Provision for uncollectible accounts		7,044			5,603
Deferred income taxes & investment tax credits		5,170			11,252
Expense portion of pension & postretirement periodic benefit cost		1,218			1,143
Equity in earnings of the Ohio operations - net of tax		(5,470	)		(7,207	)
Other non-cash charges - net		1,114			1,093
Changes in working capital accounts:
Accounts receivable, including due from Vectren companies & accrued unbilled revenue		(56,143	)		(42,059	)
Inventories		(415	)		1,104
Recoverable fuel & natural gas costs		8,775			2,412
Prepayments & other current assets		(13,060	)		3,827
Accounts payable, including to Vectren companies & affiliated companies		51,332			21,490
Accrued liabilities		7,900			10,212
Distributions from Ohio operations		-			8,448
Changes in noncurrent assets		(2,257	)		(362	)
Changes in noncurrent liabilities		(5,271	)		(5,822	)
Net cash flows from operating activities		79,056			80,619
CASH FLOWS FROM FINANCING ACTIVITIES
Requirements for:
Retirement of long-term debt, including premiums paid		(49,911	)		(37,500	)
Dividend to parent		(28,324	)		(26,504	)
Net change in short-term borrowings, including from VUHI		53,634			45,237
Net cash flows from financing activities		(24,601	)		(18,767	)
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for :
Capital expenditures		(48,617	)		(63,084	)
Other investments		(1,853	)		-
Net cash flows from investing activities		(50,470	)		(63,084	)
Cash & cash equivalents:
Net increase (decrease) in cash & cash equivalents		3,985			(1,232	)
Cash & cash equivalents at beginning of period		1,624			2,856
Cash & cash equivalents at end of period	$	5,609		$	1,624
Cash paid during the year for:
Interest	$	26,462		$	28,087
Income taxes		18,369			17,342

The accompanying notes are an integral part of these financial statements.

6

INDIANA GAS COMPANY, INC.

STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(In thousands)

	Common		Retained
	Stock		Earnings			Total
Balance at January 1, 2004	$	367,995	$	88,650		$	456,645
Net income & comprehensive income				24,436			24,436
Common stock:
Dividends to parent				(26,504	)		(26,504	)
Balance at December 31, 2004	$	367,995	$	86,582		$	454,577
Net income & comprehensive income				32,341			32,341
Common stock:
Dividends to parent				(28,324	)		(28,324	)
Balance at December 31, 2005	$	367,995	$	90,599		$	458,594

The accompanying notes are an integral part of these financial statements.

7

INDIANA GAS COMPANY, INC.

NOTES TO THE FINANCIAL STATEMENTS

1.   Organization and Nature of Operations

Indiana Gas Company, Inc. (the Company or Indiana Gas), an Indiana corporation, provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana. Indiana Gas is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Indiana Gas generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana.

Investment in the Ohio Operations

The Company holds a 47% interest in the Ohio operations, and the remaining 53% is held by Vectren Energy Delivery of Ohio, Inc. (VEDO). VEDO is also a wholly owned subsidiary of Utility Holdings. The Ohio operations provide energy delivery services to approximately 318,000 natural gas customers located near Dayton in west central Ohio. VEDO is the operator of the assets, and the Ohio operations generally do business as Vectren Energy Delivery of Ohio, Inc.

Indiana Gas’ ownership is accounted for using the equity method in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” and is included in Investment in the Ohio operations, and its interest in the results of operations is included in Equity in earnings of the Ohio operations. Additional information on the Company’s investment in the Ohio operations is included in Note 3.

2.   Summary of Significant Accounting Policies

A.   Cash & Cash Equivalents

All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.

B.   Inventories

Inventories consist of the following:

	At December 31,
(In thousands)	2005		2004
Gas in storage - at LIFO cost	$	11,338	$	11,138
Materials & supplies		2,691		1,914
Other		789		1,022
Total inventories	$	14,818	$	14,074

Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2005, and 2004, by approximately $47 million and $26 million, respectively. All other inventories are carried at average cost.

C.   Utility Plant & Depreciation

Utility plant is stated at historical cost, including AFUDC. Depreciation rates, which include a cost of removal component, are established through regulatory proceedings and are applied to all in-service utility plant. The

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original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:

	At and For the Year Ended December 31,
(In thousands)	2005					2004
	Original Cost		Depreciation Rates as a Percent of Original Cost			Original Cost		Depreciation Rates as a Percent of Original Cost
Utility plant	$	1,271,259		3.7	%	$	1,214,245		3.7	%
Construction work in progress		29,083		-			37,263		-
Total original cost	$	1,300,342				$	1,251,508

AFUDC represents the cost of borrowed and equity funds used for construction purposes, and is charged to construction work in progress during the construction period and is included in Other - net in the Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:

	Year Ended December 31,
(In thousands)	2005		2004
AFUDC – borrowed funds	$	231	$	230
AFUDC – equity funds		73		125
Total AFUDC capitalized	$	304	$	355

Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the cost of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, and Regulatory liabilities for the cost of removal. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.

D.   Impairment Review of Long-Lived Assets

Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.

E.   Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires entities to record the fair value of a liability for a legal asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

9

The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $7 million ARO for interim retirements of gas utility pipelines. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in a corresponding increase to Utility plant of approximately $7 million.

F.   Regulation

Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting customers of the Ohio operations are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).

Regulatory Assets and Liabilities

Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets.

Regulatory assets consist of the following:

	At December 31,
(In thousands)	2005		2004
Amounts currently recovered through base rates:
Unamortized debt issue costs & premiums paid to reacquire debt	$	9,768	$	10,876
Rate case expenses		360		548
		10,128		11,424
Future amounts recoverable from ratepayers:
Income taxes		7,831		8,176
Amounts currently recovered through authorized tracking mechanisms		2,003		290
Total regulatory assets	$	19,962	$	19,890

Of the $10.1 million currently being recovered through base rates, approximately $9.8 million is earning a return with a weighted average recovery period of 9.5 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.

Regulatory liabilities consist of the following:

	At December 31,
(In thousands)	2005		2004
Cost of removal	$	136,317	$	132,825
Asset retirement obligations & other		6,677		-
Total regulatory liabilities	$	142,994	$	132,825

10

Cost of Removal

The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal asset retirement obligation (ARO) as defined by SFAS No. 143.

Refundable or Recoverable Gas Costs

All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. The Company records any under-or-over-recovery resulting from gas adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers.

G.   Revenues

Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas delivered to customers but not billed at the end of the accounting period.

H.   Utility Receipts Taxes

A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of Operating revenues. Utility receipts taxes expensed are recorded as a component of Taxes other than income taxes.

I.   Earnings Per Share

Earnings per share are not presented as Indiana Gas’ common stock is wholly owned by Vectren Utility Holdings, Inc.

J.   Other Significant Policies

Included elsewhere in these notes are significant accounting policies related to the investment in the Ohio operations (Note 3), intercompany allocations and income taxes (Note 4) and derivatives (Note 10).

K.   Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

L.   Reclassifications

Certain amounts included in prior years’ balance sheet and the statements of income and cash flows have been reclassified to conform to the current year presentation. These reclassifications had no effect on reported total assets, liabilities, shareholders’ equity, or net income.

3.   Investment in the Ohio Operations

The Company’s investment in the Ohio operations is accounted for using the equity method of accounting, and the investment is periodically examined for other than temporary declines in value. The Company’s share of the Ohio operations after tax earnings is recorded in equity in earnings of the Ohio operations. Because the Ohio operations is responsible for its income taxes and is also within Vectren’s consolidated tax group, no additional tax provision for these earnings is included in these financial statements. Dividends are recorded as a reduction of the carrying value of the investment when received. Goodwill which is a component of the Company’s net investment is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 uses an impairment-only approach to account for the effect of goodwill on the operating results.

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Following is summarized financial data of the Ohio operations:

	Year Ended December 31,
(In thousands)	2005		2004
Operating revenues	$	395,383	$	329,729
Gas operating margin		115,057		104,020
Operating income		11,230		15,600
Net income		11,637		15,334
		At December 31,
(In thousands)		2005		2004
Net utility plant	$	301,399	$	285,244
Current assets		171,715		142,341
Goodwill - net		199,457		199,457
Other non-current assets		11,099		9,826
Total assets	$	683,670	$	636,868
Owners' net investment	$	431,218	$	431,618
Current liabilities		141,510		110,264
Noncurrent liabilities		110,942		94,986
Total liabilities & owners' net investment	$	683,670	$	636,868

Gas Cost Recovery (GCR) Audit Proceedings

On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO, which is the operator of the Ohio operations, and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During the fourth quarter of 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.2 million was recorded in Cost of Gas Sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.

VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company has filed an appeal on that decision as well. The brief on both issues is due May 1, 2006 and briefing should be complete in June, 2006.

In addition, the Company solicited and received bids for VEDO’s gas supply and portfolio administration services and has selected a third party provider, who began providing services to VEDO on November 1, 2005, under a one year contract.

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VEDO Base Rate Settlement

On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate design includes a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in VEDO’s service territory was implemented on April 14, 2005. VEDO’s new base rates provide for the recovery of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.

4.   Transactions with Other Vectren Companies

Support Services and Purchases

Vectren and certain subsidiaries of Vectren provide corporate and general and administrative services to the Company including legal, technology, finance, tax, risk management, and human resources, which includes charges for restricted stock compensation and for pension and other postretirement benefits not directly charged to subsidiaries. In addition, the Company receives a charge for the use of common corporate assets, such as office space and computer hardware and software. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are primarily based on cost. Indiana Gas received corporate allocations totaling $60.7 million and $56.7 million for the years ended December 31, 2005, and 2004, respectively.

Retirement Plans and Other Postretirement Benefits

Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 “Employers’ Accounting for Pensions” and SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. An allocation of cost is determined by Vectren’s actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the SFAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with “multiemployer” benefit accounting as described in SFAS 87 and 106.

For the years ended December 31, 2005, and 2004, periodic pension costs totaling $1.4 million and $1.3 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2005, and 2004, other periodic postretirement benefit costs totaling approximately $0.3 million were directly charged by Vectren to the Company. As of December 31, 2005, and 2004, $14.5 million and $18.3 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren, and $3.0 million and $2.4 million, respectively, is included in Other assets for amounts funded in advance to Vectren.

Cash Management and Borrowing Arrangements

The Company participates in a centralized cash management program with Vectren and other wholly owned subsidiaries. See Note 6 regarding long-term and short-term intercompany borrowing arrangements.

Share-Based Incentive Plans

In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that will require compensation costs related to all share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to January 1, 2006 for calendar year companies like Indiana Gas. The Company intends to adopt SFAS 123R using the modified prospective method. The adoption of this standard, and subsequent interpretations of the standard, is not expected to have a material effect on the Company’s operating results or financial condition.

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Guarantees of Parent Company Debt

Vectren’s three operating utility companies, Indiana Gas, Southern Indiana Gas and Electric Company, Inc. (SIGECO) and VEDO are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which approximately $226.9 million is outstanding at December 31, 2005, and Utility Holdings’ $700 million unsecured senior notes outstanding at December 31, 2005. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.

Income Taxes

Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Indiana Gas’s current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash.

A reconciliation of the federal statutory rate to the effective income tax rate follows:

	Year Ended December 31,
	2005			2004
Statutory rate		35.0	%		35.0	%
State & local taxes, net of federal benefit		6.2			7.4
Amortization of investment tax credit		(2.1	)		(3.2	)
Adjustment to income tax accruals & other, net		(0.2	)		(0.4	)
Effective tax rate		38.9	%		38.8	%

The components of income tax expense and utilization of investment tax credits follow:

	Year Ended December 31,
(In thousands)	2005			2004
Current:
Federal	$	8,367		$	(1,800	)
State		3,551			1,463
Total current taxes		11,918			(337	)
Deferred:
Federal		4,968			10,422
State		1,106			1,744
Total deferred taxes		6,074			12,166
Amortization of investment tax credits		(904	)		(914	)
Total income taxes	$	17,088		$	10,915

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The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:

	At December 31,
(In thousands)	2005			2004
Non-current deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	81,808		$	78,826
Regulatory assets recoverable through future rates		9,625			10,080
Regulatory liabilities to be settled through future rates		(1,793	)		(1,904	)
Employee benefit obligations		(6,959	)		(9,982	)
Other – net		(701	)		(1,444	)
Net non-current deferred tax liability		81,980			75,576
Current deferred tax liability:
Deferred fuel costs - net		2,055			2,729
Net deferred tax liability	$	84,035		$	78,305

At December 31, 2005, and 2004, investment tax credits totaling $2.6 million and $3.5 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.

5.   Transactions with Vectren Affiliates

ProLiance Energy, LLC

ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to Indiana Gas, other Vectren companies, Citizens Gas and a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions. ProLiance’s primary business is optimizing the gas portfolios of utilities and providing services to large end use customers.

Transactions with ProLiance

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2005, and 2004, totaled $604.6 million and $479.5 million, respectively. Amounts owed to ProLiance at December 31, 2005, and 2004, for those purchases were $115.7 million and $61.8 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.

As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreement with the Company was approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company through March 2011. The settlement is subject to approval by the IURC.

Other Affiliate Transactions

Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2005, and 2004, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled approximately $12.0 million and $20.9 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates of Vectren, other than ProLiance, totaled $1.5 million and $0.8 million at December 31, 2005, and 2004, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets.

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6.   Borrowing Arrangements & Other Financing Transactions

Short-Term Borrowings

As of December 31, 2005, the Company has no short-term borrowing arrangements with third parties and relies entirely on the short-term borrowing arrangements of Utility Holdings for short-term working capital needs. Borrowings outstanding at December 31, 2005, and 2004, were $162.8 million and $109.2 million, respectively. The intercompany credit line is limited by Utility Holdings’ available capacity, which is $293.0 million at December 31, 2005. The line is subject to the same terms and conditions as Utility Holdings’ commercial paper program. Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds.

See the table below for interest rates and outstanding balances.

	Year ended December 31,
(In thousands)	2005			2004
Weighted average total outstanding during
the year due from Utility Holdings (in thousands)	$	48,336		$	31,151
Weighted average interest rates during the year:
Utility Holdings		3.61	%		1.86	%

Long-Term Debt

Senior unsecured obligations outstanding and classified as long-term follow:

	At December 31,
(In thousands)	2005		2004
Fixed Rate Senior Unsecured Notes Payable to Utility Holdings:
2011, 6.625%	$	98,953	$	98,953
2018, 5.75%		37,129		37,140
2031, 7.25%		48,355		48,355
Total long-term debt payable to Utility Holdings	$	184,437	$	184,448
Fixed Rate Senior Unsecured Notes Payable to Third Parties:
2007, Series E, 6.54%	$	6,500	$	6,500
2013, Series E, 6.69%		5,000		5,000
2015, Series E, 7.15%		5,000		5,000
2015, Series E, 6.69%		5,000		5,000
2015, Series E, 6.69%		10,000		10,000
2025, Series E, 6.53%		10,000		10,000
2027, Series E, 6.42%		5,000		5,000
2027, Series E, 6.68%		1,000		1,000
2027, Series F, 6.34%		20,000		20,000
2028, Series F, 6.36%		10,000		10,000
2028, Series F, 6.55%		20,000		20,000
2029, Series G, 7.08%		30,000		30,000
2030, Insured Quarterly, 7.45%		-		49,917
Total long-term debt outstanding payable to third parties		127,500		177,417
Debt subject to tender		-		(10,000	)
Long-term debt payable to third parties - net of current maturities & debt subject to tender	$	127,500	$	167,417

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Debt Call

In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2005 and 2004 had stated interest rates of 7.45% and 7.15%, respectively.

Long-Term Debt Sinking Fund Requirements & Maturities

Maturities and sinking fund requirements on long-term debt during the five years following 2005 (in millions) are zero in 2006, $6.5 in 2007, and zero in 2008, 2009 and 2010.

Long-Term Debt Put & Call Provisions

Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. Debt which may be put to the Company during the years following 2005 (in millions) is zero in 2006, $20.0 in 2007, zero in 2008 and 2009, $10.0 million in 2010, and $30.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.

Covenants

Borrowing arrangements contain customary default provisions; restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2005, the Company was in compliance with all financial covenants.

7.   Commitments & Contingencies

Legal Proceedings

The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 regarding environmental matters.

8.   Environmental Matters

In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites.

Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.

In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million.

The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%.

With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.

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Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen.

9.   Rate & Regulatory Matters

Gas Base Rate Settlement

On November 30, 2004, the IURC approved a $24 million base rate increase for Indiana Gas’ gas distribution business. The new rate design includes a larger service charge, which is intended to address to some extent earnings volatility related to weather.

The order also permits Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $2.5 million per year thereafter. Any costs incurred in excess of these annual caps are to be deferred for future recovery.

Decoupling/Conservation Filing

On October 25, 2005, Indiana Gas, along with SIGECO, filed with the IURC for approval of a conservation program and a conservation adjustment rider in their two Indiana service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company will file its evidence in March 2006 and a hearing is set for June 2006.

Weather Normalization

On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Indiana Gas. The OUCC had previously entered into a settlement agreement with the Company providing for the NTA. The NTA affects the Company’s residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These customer classes represent approximately 88% of the Company’s total natural gas margin.

The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA has been applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven month heating season will be adjusted using the NTA.

The order provides that the Company will make, on a monthly basis, a commitment of $110,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.

Commodity Prices

Commodity prices for natural gas purchases have remained above historic levels and have become more volatile. Subject to compliance with applicable state laws, the Company is allowed recovery of such changes in purchased gas costs from its retail customers through a commission-approved gas cost adjustment mechanism, and margin on gas sales are not expected to be impacted. Nevertheless, it is possible the regulator may disallow recovery of a portion of gas costs for a variety of reasons, including, but not limited to, a finding by the regulator that natural gas was not prudently procured. In addition, it is reasonably possible that as a result of this near term change in the natural gas commodity price, the Company may experience increased interest expense due to higher working capital requirements; increased uncollectible accounts expense and unaccounted for gas; and some level of price sensitive reduction in volumes sold or delivered. In response to higher gas prices, Utility Holdings increased its credit facilities, on which the Company relies for its short-term working capital needs.

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10.   Derivatives & Other Financial Instruments

Accounting Policy for Derivatives

The Company executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.

When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (normal exception), it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying’s basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting related to natural gas procurement.

The Company has limited exposure to commodity price risk for purchases and sales of natural gas for retail customers due to current Indiana regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas adjustment mechanisms. Although the Company is exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price volatility of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2005 and 2004, the market values of these contracts were not significant.

Fair Value of Other Financial Instruments

The carrying values and estimated fair values of the Company's other financial instruments follow:

	At December 31,
	2005				2004
(In thousands)	Carrying Amount Est. Fair Value				Carrying Amount Est. Fair Value
Long-term debt due to third parties	$	127,500	$	137,048	$	177,417	$	184,300
Long-term debt due to Utility Holdings		184,437		193,970		184,448		202,406
Short-term debt due to Utility Holdings		162,845		162,845		109,211		109,211

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's other financial instruments was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.

Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's financial position or results of operations.

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11.   Additional Operational & Balance Sheet Information

Other - net in the Statements of Income consists of the following:

	Year Ended December 31,
(In thousands)	2005			2004
AFUDC	$	304		$	355
Other income		868			381
Donations		(1,929	)		(1,635	)
Other expense		(144	)		(129	)
Total other – net	$	(901	)	$	(1,028	)

Prepayments and other current assets in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2005		2004
Prepaid gas delivery service	$	69,330	$	58,490
Prepaid taxes		10,165		7,069
Other prepayments & current assets		7		883
Total prepayments & other current assets	$	79,502	$	66,442

Accrued liabilities in the Balance Sheets consist of the following:

	At December 31,
(In thousands)	2005		2004
Customer advances & deposits	$	17,008	$	13,618
Accrued gas imbalance		10,784		7,811
Accrued taxes		10,557		11,125
Accrued interest		4,551		4,204
Deferred income taxes		2,055		2,729
Accrued salaries & other		12,938		9,852
Total accrued liabilities	$	57,893	$	49,339

12. Adoption of Other Accounting Standards

SFAS No. 154

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement in the instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of the direct effects caused by a change in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Further, changes in depreciation, amortization or depletion methods for long-lived, nonfinancial assets are to be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted. The adoption of this standard, beginning in fiscal year 2006, is not expected to have any material effect on the Company’s operating results or financial condition.

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The following discussion and analysis should be read in conjunction with the financial statements and notes thereto and the annual reports filed on Forms 10-K of both Vectren and Utility Holdings.

Executive Summary of Results of Operations

Indiana Gas generates revenue primarily from the delivery of natural gas service to its customers. The primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas services. Results are impacted by weather patterns in its service territory and general economic conditions both in its service territory as well as nationally.

For the year ended December 31, 2005, earnings were $32.3 million as compared to $24.4 million in 2004. The 2005 results reflect the impact of a regulatory strategy that includes a gas utility base rate increase and a normal temperature adjustment mechanism implemented in October 2005, among other initiatives. Gas utility base rate increases added revenues of approximately $19.9 million, or $11.8 million after tax, in 2005 compared to 2004. The increase was partially offset by higher operating expenses and lower earnings from the Ohio operations.

Management estimates that the impact of weather, including the effects of the recently implemented normal temperature adjustment mechanism, was unfavorable $3.6 million after tax in 2005 and $4.3 million after tax in 2004.

Significant Fluctuations

Gas Operating Margin

Margin generated from the sale of natural gas to residential and commercial customers is seasonal and impacted by weather patterns in the Company’s service territories. The weather impact is mitigated somewhat by a normal temperature adjustment mechanism, which was implemented in the fourth quarter of 2005. Margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, and is also impacted by some level of price sensitivity in volumes sold. Following is a discussion and analysis of margin generated from regulated utility operations.

	Year Ended December 31,
(In millions)	2005		2004
Gas utility revenues	$	831,741	$	686,103
Cost of gas sold		595,940		474,452
Total gas utility margin	$	235,801	$	211,651
Margin attributed to:
Residential & commercial customers	$	203,864	$	183,646
Industrial customers		27,046		26,652
Other customers		4,891		1,353
Sold & transported volumes in MDth attributed to:
Residential & commercial customers		64,111		63,755
Industrial customers		51,510		50,898
Total sold & transported volumes		115,621		114,653

Gas utility margins were $235.8 million for the year ended December 31, 2005, an increase of $24.1 million compared to 2004. The increase is primarily due to the favorable impact of the gas base rate increase of $19.9 million, higher miscellaneous revenues of $1.5 million, and additional pass through revenue taxes recovered in margins of $2.2 million compared to last year. Management estimates that weather, including of the effects of the normal temperature adjustment mechanism, increased margin an estimated $1.2 million compared to 2004. Though estimated to be modest to date and net of customer growth, management has seen evidence of gas customer usage declines in 2005, assumed to be driven primarily by price sensitivity. With the current outlook for continued high gas commodity prices, management expects that trend to continue and/or accelerate in 2006. The average cost per dekatherm of gas purchased was $9.15 in 2005 and $7.10 in 2004.

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Operating Expenses

Other Operating

Other operating expenses increased $4.9 million for the year ended December 31, 2005, as compared to 2004. The increase is attributable to higher administrative costs, including performance-based compensation and benefit costs increases, of $3.0 million, increased uncollectible accounts of $1.4 million, and higher maintenance expenses of $0.5 million as compared to 2004.

Depreciation & Amortization

For the year ended December 31, 2005, depreciation expense increased $1.7 million compared to 2004. The increase resulted primarily from normal additions to utility plant.

Income Taxes

For the year ended December 31, 2005, income taxes increased $6.2 million compared to 2004, primarily due to increased earnings before taxes.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3.2 million in 2005 compared to 2004. The increase is primarily due to increased collections of utility receipts taxes due to higher revenues.

Other Income

Equity in Earnings of the Ohio Operations

Equity in earnings of the Ohio operations represents Indiana Gas’ 47% interest in the Ohio operations’ net income. The financing costs associated with VEDO’s 53% ownership interest are not included in the Ohio operations’ equity in earnings. The Ohio operations’ net income was $11.6 million in 2005 and $15.3 million in 2004. Indiana Gas’ share of those earnings was $5.5 million and $7.2 million, respectively. The effects of a base rate increase was more than offset by a $4.2 million ($2.5 million after tax) charge recorded pursuant to the disallowance of Ohio gas costs in 2005, as well as higher operating expenses and depreciation expense. Depreciation expense in 2004 was affected by a true-up of depreciation rates to existing regulatory orders which decreased depreciation expense in that year. Interest costs arising from financing arrangements utilized for the purchase of the Ohio operations are not reflected in the above financial information. Had the financing arrangements of Indiana Gas and VEDO used to facilitate the purchase of the Ohio operations been pushed down, the Ohio operations’ net income would have been approximately $2.3 million and $6.0 million for the years ended December 31, 2005 and 2004, respectively. 

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SELECTED GAS OPERATING STATISTICS:

INDIANA GAS
SELECTED UTILITY
OPERATING STATISTICS
(Unaudited)
	For the Year Ended
	December 31,
	2005			2004
OPERATING REVENUES (In thousands):
Residential	$	561,809		$	466,106
Commercial		229,440			184,578
Industrial		35,599			34,065
Misc Revenue		4,893			1,354
	$	831,741		$	686,103
MARGIN (In thousands):
Residential	$	155,825		$	141,875
Commercial		48,039			41,771
Industrial		27,046			26,652
Misc Revenue		4,891			1,353
	$	235,801		$	211,651
GAS SOLD & TRANSPORTED (In MDth):
Residential		44,623			44,660
Commercial		19,488			19,095
Industrial		51,510			50,898
		115,621			114,653
YEAR END CUSTOMERS:
Residential		511,926			507,139
Commercial		49,259			48,588
Industrial		869			889
		562,054			556,616
WEATHER AS A % OF NORMAL:
Heating Degree Days		95	%		91	%

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